1

MEMORANDUM

TO: Jim Eddinger, U.S. Environmental Protection Agency, O AQPS/SPPD

FROM: Graham Gibson, Susan McClutchey, and Amanda Single ton, ERG

DATE: February 17, 2011

SUBJECT: Revised Methodology for Estimating Impacts from Industrial, Commercial, Institutional Boilers at Area Sources of Hazardous Air Pollutant Emissions



## 1.0 INTRODUCTION

The purpose of this memorandum is to discuss the methodology used to estimate the costs, emission reductions, and secondary impacts from i ndustrial, commercial, and institutional boilers at area sources of hazardous air pollutants (HAP) . These impacts were calculated for existing units and new units projected to be operational th ree years after the rule is expected to be promulgated. The results of the impacts analysis ar e presented for both the most stringent regulatory option evaluated and the regulatory option conta ined in the final rule. The development of the maximum achievable control technology (MACT) floor and Generally Achievable Control Technology (GACT) level of control, projection of new units, and a detailed description of the cost equations used to estimate costs for various control technologies is presented in other memoranda. 1,2,3 This memorandum is organized as follows:

1.0 Introduction

2.0 Overview of Regulatory Options

3.0 Estimating Cost Impacts

4.0 Methodology for Estimating Emission Reductions

5.0 Methodology for Estimating Secondary Impacts

6.0 References2



## 2.0 OVERVIEW OF REGULATORY OPTIONS

Four control options were considered for existing boiler s at area sources of HAP. A description of the four options is described below.



### 2.1 Existing Units

• Option 1E represents the option where all boilers, regar dless of fuel type or size, must meet mercury and CO numerical emission limits based on MACT and PM numerical emission limits based on GACT. PM GACT was identified to be a multiclone for existing units.

• Option 2E represents the same emission limits as discuss ed in 1E above for large units (equal to or greater than 10 mmBtu/hr). Small units are exe mpt from numerical limits and instead are required to meet a work practice standard of a bi ennial tune-up. All facilities are required to conduct an energy assessment.

• Option 3E represents the option in which all coal boiler s equal to or greater than 10 mmBtu/hr must meet mercury and CO numeric emission limi ts based on MACT. All biomass and liquid boilers equal to or greater than 10 mmBtu/ hr must meet a CO numerical emission limit, based on MACT. All facili ties with a large boiler are required to conduct an energy assessment. Small boilers are ex empt from numeric emission limits for all pollutants, but are required to meet a work pract ice standard of a biennial tune-up. There are no numerical emission limits for PM under t his option for any size or type of unit.

• Option 4E represents the option which is discussed most prominently in the preamble. In this option, all coal boilers equal to or greater than 10 mmBtu/hr must meet mercury and CO numeric emission limits based on MACT. All biomas s and liquid boilers must comply with GACT for urban HAP, which is a boiler tune -up. All facilities with a large boiler are required to conduct an energy assessment. Smal l coal-fired boilers are exempt from numeric emission limits for all pollutants, but a re required to meet a work practice standard of a biennial tune-up. There are no numerical emis sion limits for PM under this option for any size or type of unit.



### 2.2 New Units

Four control options were considered for new boilers a t area sources of HAP. A detailed description of the four options is described below.

• Option 1N represents the option where all boilers, rega rdless of fuel type or size, must3

meet mercury and CO limits based on MACT and PM numeric al emission limits based on GACT. GACT for new units is based on PM limits in t he New Source Performance Standards (NSPS) for Industrial, Commercial, and Institut ional Boilers (40 CFR part 60 subparts Db, Dc).

• Option 2N represents the same emission limits as discus sed in 1N above for large units (equal to or greater than 10 mmBtu/hr). Small units are exe mpt from numerical emission limits and instead are required to meet a work practice sta ndard of a biennial tune-up.

• Option 3N requires all coal boilers, regardless of size, must meet mercury and CO limits based on MACT and PM numerical emission limits based o n GACT. All biomass and liquid boilers, regardless of size, must meet CO limit s based on MACT and PM numerical emission limits based on GACT.

• Option 4N - represents the option in which all coal boi lers equal to or greater than 10 mmBtu/hr must meet mercury and CO numeric emission limi ts based on MACT. All biomass and liquid boilers must comply with GACT , which is a tune-up. Small boilers coal-fired are exempt from numeric emission limits for all pollutants, but are required to meet a work practice standard of a biennial tune-up. All units greater than 10 mmBtu/hr have PM emission limits based on GACT. The emission limit changes for units greater than 30 mmBtu/hr.



## 3.0 ESTIMATING COST IMPACTS

For each option, a percentage of units in each model u nit were assumed to require control

devices in order to meet the limit when the baseline emi ssions for the model unit exceeded the MACT floor emission limit applicable to each model. A de tailed description of the options is described below. A summary table comparing the overall cap ital and annualized costs of option 4E for existing units and option 4N for new units is present ed in Table 1. The cost, emission reduction, and secondary impacts summarized here and in Se ctions 4, and 5, respectively, reflect the impacts for new units when using the NSPS limit of 0. 03 lb/mmBtu for PM. The equations used to estimate the control, testing, monitoring, and wo rk practice costs are discussed in another

memorandum. 3 The following logic was used to apply control, testing, and monitoring costs to

each boiler:4



### 3.1 Option 1E

Control Cost Impacts

Mercury Control A new fabric filter installation was expected to achi eve the mercury emission limits in the final rule. Where baseline mercury emissions were found to be greater than the MACT floor, the cost of a fabric filter was estimated for a portion of the boilers represented by the model unit. Based on the data used in the MACT floor analysis, a fr action of units in each subcategory meeting the MACT floor for Hg was estimated. For boilers designed to burn biomass one of the boilers was meeting the floor and the other unit was not meeting the floor. In the cost impact s analysis, 50 percent of the biomass units

were estimated to install a fabric filter to meet the floor. For boilers designed to burn coal, 86 percent of units were achieving the MACT floor emission li mit for coal, so a new fabric filter was estimated to be installed at 14 percent of the existi ng coal-fired boilers. For liquid fuel units,

there were no area source boilers with emission tes t data available for mercury. In the absence of

other information about the distribution of units that woul d require a fabric filter to be installed, this cost impacts analysis assumes that 50 percent of t he liquid fuel units would install a fabric filter to meet the mercury limit.

CO/Organic HAP Control Organic HAP and carbon monoxide can be controlled by eithe r improving the combustion efficiency of the unit, or installing an oxidati on catalyst on the exhaust of a combustion unit. The control strategy necessary to me et the MACT floor emission limit will vary depending on the magnitude between the baseline emissions an d the CO MACT floor. Most boilers are designed to operate with CO emissions at or near 400 parts per million (ppm). A boiler tune-up was estimated in the cost impacts analysis if the unit’s baseline emissions exceeded the floor for carbon monoxide (CO) , but were less than or equal to 400 ppm

@ 3% O 2 . The combustor design of the boilers in the area sour ce inventory is not known and this impacts analysis assumes that all areas source boiler s firing solid fuels have a stoker combustor design since this is the predominant combustor design in th e major source boiler inventory. The5

baseline emissions for area source boilers in all fuel categories are less than 400 ppm, and so it is assumed that combustion controls, either a basic tun e-up or a more advanced burner replacement or installation of a linkageless boiler management syst em, can achieve the MACT floor emission limits. No oxidation catalysts are estimated to be requi red to meet the MACT floor emission

limits.

Based on the emission test data used to calculate the MA CT floor for CO, 29 percent of units burning coal are exceeding the MACT floor and these uni ts would be expected to install a linkageless boiler management system to comply with the CO limits. For units burning biomass, 69 percent of the units are exceeding the MACT floor emissi on limits, and so 69 percent of the units are estimated to install a linkageless boiler manag ement system. For units burning liquids, 10 percent of the units are exceeding the floor and this cos t impacts analysis assumes these units will install a new low NOx replacement burner in order to meet the CO limits. The units not expected to install these advanced controls are expecte d to conduct an annual tune-up to maintain in compliance with the proposed CO limit overtime.

Particulate Matter Control For all units that were not expected to install a fabri c filter for mercury control, the cost impacts analysis for this option assumes that the unit would install a multiclone to achieve the

GACT emission limits for PM. Based on the current MAC T floor analysis, 44 percent of coal units and 50 percent of liquid units would install a multiclone . Existing biomass units not expected to install a fabric filter would also install a multiclone. Base on the current MACT floor analysis, 50 percent of existing biomass units would in stall a multiclone.



### Testing and Monitoring Cost Impacts

Testing and monitoring requirements varied depending on the e quipment installed on the unit to control emissions, the design capacity of the mo del unit, and the fuel category of the

model unit.

Testing Costs All boilers designed to burn solid fuels were expected to co nduct an annual compliance6

test for PM, Hg, and CO. The cost to conduct stack test s for these three pollutants was estimated to be $15,000 per year. Boilers designed to burn liquid fuels were expected to conduc t an annual compliance test for PM and CO. In lieu of a stack test boilers designed to burn liquid fuels were expected to conduct fuel analysis, or report fuel analyses received f rom a fuel supplier for chlorine and Hg. Conducting stack tests for PM and CO was estimated to be $13, 000 per year and the cost to conduct fuel analysis for Hg was estimated to be $600 per ye ar. Although solid fuels are eligible to comply with the rule through fuel analysis in lieu of s tack testing, when the mercury content of the fuel is below the MACT floor emission limit, this cost estimate conservatively assumed that only units designed to fire liquid fuels would use this c ompliance alternative. The methods and data sources used to estimate testing and monitoring cost s are discussed in other

memoranda. 3

Monitoring Costs Various monitor configurations were installed based on the size of the unit and the pollution control devices expected to be installed to achieve the MACT floor emission limits. For units expected to install a fabric filter, an annualized cos t of $9,700 for a bag leak detection monitor was included in the cost analysis. For units tha t did not install a bag leak detector, an annualized cost of $14,660 for an opacity monitor was included in the cost analysis.



### Fuel Savings Impacts This cost analysis includes an estimate of energy saving s for every unit that is expected to install controls to improve combustion, or conduct an ann ual tune-up or energy assessment. The Department of Energy has conducted energy assessments at selected manufacturing facilities and reports that facilities can reduce fuel/energy use by 10 to 15 percent by using best practices to increase their energy efficiency. Many best practices are considered pollution prevention because they reduce the amount of fuel combusted which re sults in a corresponding reduction in

emissions from the fuel combustion. Further boiler t une-ups have been shown to improve the efficiency of a boiler between 1 and 5 percent, depending o n the age of the unit and the time lapse since the previous tune-up. Other combustion controls such as upgrading burners and installation of an LBMS are also expected to improve the efficiency of the unit, thus reducing7

fuel consumption. This cost analysis assumes an annual fue l savings of 1 percent. The energy savings is estimated using Equation 1:

Annual Fuel Savings (mmBtu/yr) = DC * CF * Op hours * EG (Equation 1) Where: DC = unit design capacity (mmBtu/hr) Op hours = annual operating hours, assumed 8400 (hours/year) EG = Efficiency gain, estimated to be 1% CF = annual average capacity factor, 0.5 for liquid and 0.65 for coal and biomass

After the fuel savings for each boiler was calculated, the both industrial and commercial prices for coal, #2 distillate fuel oil, and #6 residual fuel oil were obtained from the EIA. 3 The EIA data reported fuel prices as $/ton for coal, and cen ts per gallon for fuel oil. The higher heating values were obtained from Table C-1 of the EPA Ma ndatory Reporting Rule (40 CFR part 98 subpart C) and the higher heating values were used to co nvert the fuel prices to a standard unit of measure, $ per mmBtu. Using the distribution of SIC codes reported in the 13- state boiler inspector inventory, the model units were dis tributed to an industrial or commercial sector, and then the appropriate fuel price was multiplied by the calculated fuel savings. This cost analysis only estimates the fuel savings from units i n the coal and liquid fuel categories. A fuel savings was not estimated for units in the biomass fuel category since the price of biomass fuels is variable, and often biomass is an on-site industr ial byproduct instead of a purchased fuel.



### 3.2 Option 2E Option 2E follows the same logic for estimating contro l costs as option 1E outlined above, with the exception of small units (less than 10 m mBtu/hr). In option 2E, the only cost

estimated for small units is the cost of an annual tune- up for each boiler. No testing and monitoring costs were included in option 2E for small units . Option 2E also includes the cost of an energy assessment at every area source facility, approximately 91,339 facilities. As discussed in the memorandum for Estimating Control Costs from M ajor Source Boilers and Process heaters, the cost of an energy assessment ranges fro m $75,000 for industrial-scale energy assessments to between $2,000 and $5,000 per energy assessment f or institutional and

commercial-scale assessments. 4 The facility’s classification of either an industria l or commercial facility was assigned using the distribution of SIC codes in the 13-state boiler inspector8

inventory. The cost of each type of assessment was annua lized over 5 years at 7 percent to obtain

an annualized cost estimate.



### 3.3 Option 3E Option 3E includes control device and testing/monitoring cos t estimation for mercury and CO from large coal units. As mentioned in option 1E, 56 pe rcent of large coal units, or 321 boilers are expected to install a fabric filter in orde r to meet the mercury limit. In addition, 29 percent of large coal units are expected to install adva nced combustion controls in order to meet the CO limit. This analysis uses the cost of a linkagele ss boiler management system to estimate the costs of advanced combustion control. The remaining 71 pe rcent of large coal units are expected to meet the CO limit with a tune-up. The testin g and monitoring costs for large coal units include a test for CO and mercury, as well as a bag l eak detection system for the 321 boilers that are expected to install a fabric filter. There are no numerical PM emission limits under this option, and so no additional testing costs for PM or opacity monitoring costs were assessed in the cost impacts analysis for this option. Under option 3E liquid and biomass boilers are not subject to numerical emission limits for mercury and there are no costs included in the impac ts analysis to install fabric filters or conduct mercury fuel analysis or stack testing. Large liqu id and biomass boilers are subject to numerical emission limits for CO. This cost impacts analysis estimates that all the biomass and liquid fuel units can meet the CO emission limits by con ducting an annual tune-up. These large units must also conduct testing and monitoring activities for CO to demonstrate compliance with

the numerical emission limits. Option 3E exempts small boilers from numerical emissio n limits. Instead these units must conduct a work practice standard of a biennial tune-up. The cos t impacts analysis does not include any additional testing and monitoring requirements fo r these small boilers. Finally, option 3E proposes that all facilities with la rge boilers conduct an energy assessment. For this cost impacts analysis one large b oiler per facility was assumed, or 13,268

facilities estimated to conduct an assessment. Similar to the discussion under option 2E, the cost of the assessment ranged from $75,000 for industrial-scale e nergy assessments to between $2,000 and $5,000 per energy audit for institutional and commercia l-scale assessments. 29



### 3.4 Option 4E Option 4E includes control device and testing/monitoring cos t estimation for mercury and CO from large coal units. As mentioned in option 1E, 14 pe rcent of large coal units, or 80 boilers are expected to install a fabric filter in order to mee t the mercury limit. In addition, 19 percent of large coal units are expected to install advanced combustio n controls in order to meet the CO limit. This analysis uses the cost of a linkageless boi ler management system to estimate the costs of advanced combustion control. The remaining 81 percent of large coal units are expected to meet the CO limit with a tune-up. The testing and monitor ing costs for large coal units include a test for CO and mercury, as well as a bag leak detection system and oxygen monitoring for the 80 boilers that are expected to install a fabric filter. There are no numerical PM emission limits under this option, and so no additional testing costs for PM or opacity monitoring costs were assessed in the cost impacts analysis for this option. Under option 4E liquid and biomass boilers are not subject to numerical emission limits for mercury or CO and there are no costs included in the impacts analysis to install control equipment or conduct mercury or CO fuel analysis or stack testing. This cost impacts analysis includes the cost of a biennial tune-up for all the biomass a nd liquid fuel. Option 4E exempts small coal-fired boilers from numerica l emission limits. Instead these units must conduct a work practice standard of a biennial tune -up. The cost impacts analysis does not include any additional testing and monitoring requireme nts for these small boilers. Finally, option 4E proposes that all facilities with la rge boilers conduct an energy assessment. For this cost impacts analysis one large b oiler per facility was assumed, or 13,268

facilities estimated to conduct an assessment. Similar to the discussion under option 2E, the cost of the assessment ranged from $75,000 for industrial-scale e nergy assessments to between $2,000 and $5,000 per energy assessment for institutional and com mercial-scale assessments. 2



### 3.5 

### Option 1N New area source boilers are subject to an NSPS (40 CFR part 60 subparts Db, Dc) to regulate emissions of PM, NOx and SO2. The cost impacts analysis considered controls that would likely be installed to comply with the NSPS and inc ludes an estimate of any additional control, testing and monitoring costs that would not be a lready conducted to meet the requirements of the NSPS. Based on a review of the NSP S, this analysis assumes all biomass10

boilers greater than 30 mmBtu/hr will have an ESP contro l installed as the baseline to meet the NSPS PM limits; all coal boilers greater than 75 will have an FF and wet scrubber installed to meet PM and SO2 limits; all coal boilers between 30 and 75 will have a Fabric Filter and use low sulfur coal to meet PM and SO2 limits, and all liquid boil ers greater than 30 will have an FF installed to meet PM limits. The NSPS does not regulate PM for units less than 30 mmBtu/hr.

Mercury Control A new fabric filter installation was expected to achi eve the mercury emission limits in the final rule. Where baseline mercury emissions were found to be greater than the MACT floor, the cost of a fabric filter was estimated for a portion of the boilers represented by the model unit. All new boilers, regardless of size or fuel, were expected t o install a fabric filter in order to meet the mercury limits under this option. Comparing these mercury control requirement to the expected controls under the NSPS, all biomass boilers are expec ted to install a fabric filter to meet the mercury limit and all liquid and coal boilers less than o r equal to 30 mmBtu/hr are expected to install a fabric filter to meet the mercury limit.

CO/Organic HAP Control New boilers are expected to be equipped with new and effici ent burners, and it was assumed that an annual tune-up could achieve the CO numeric emission limit for all sizes and types of boilers. Other advanced combustion controls we re not considered as a control alternative for new boilers. As mentioned under 1E, the control str ategy necessary to meet the MACT floor emission limit will vary depending on the magnitude between the baseline emissions and the CO

MACT floor.

Particulate Matter Control Under this option all units are expected to install a f abric filter for mercury control, which has a co-benefit of reducing PM emissions, as well as other non-mercury metallic HAP. No

additional control costs were estimated for PM contro l at new boilers.



### Testing and Monitoring Cost Impacts11

Testing and monitoring requirements varied depending on the e quipment installed on the unit to control emissions, the design capacity of the mo del unit, and the fuel category of the

model unit.

Testing Costs All boilers designed to burn solid fuels were expected to co nduct an annual compliance test for PM, Hg, and CO. The cost to conduct stack test s for these three pollutants was estimated to be $15,000 per year. Boilers designed to burn liquid fuels were expected to conduct an annual compliance test for PM and CO. In lieu of a stack test boilers designed to burn liquid fuels were expected to conduct fuel analysis, or report fuel analyses received f rom a fuel supplier for chlorine and Hg. Conducting stack tests for PM and CO was estimated to be $13, 000 per year and the cost to conduct fuel analysis for Hg was estimated to be $600 per ye ar. Although solid fuels are eligible to comply with the final rule through fuel analysis in l ieu of stack testing, when the mercury

content of the fuel is below the MACT floor emission limit, this cost estimate conservatively assumed that only units designed to fire liquid fuels would us e this compliance alternative. The methods and data sources used to estimate testing and monito ring costs are discussed in other

memoranda. 3

Monitoring Costs Various monitor configurations were installed based on the size of the unit and the pollution control devices expected to be installed to achieve the MACT floor emission limits. For units expected to install a fabric filter, an annualized cos t of $9,700 for a bag leak detection monitor was included in the cost analysis. For units tha t did not install a bag leak detector, an annualized cost of $14,660 for an opacity monitor was included in the cost analysis.



### 3.6 

### Option 2N Option 2N follows the same logic for estimating contro l costs as option 1N outlined above, with the exception of small units (less than 10 m mBtu/hr). In option 2N, the only cost

estimated for small units is the cost of an annual tune- up for each boiler. No testing and monitoring costs were included in option 2N for small units12



### 3.7 Option 3N Option 3N includes identical requirement for coal units as outlined under option 1N. Under option 3N liquid and biomass boilers are not subject to numerical emission limits for mercury and there are no costs included in the impacts a nalysis to install fabric filters for mercury control or conduct mercury fuel analysis or stack testing. Liquid and biomass boilers are subject to numerical emission limits for CO. This cost impacts analysis estimates that all the biomass and liquid fuel units can meet the CO emission li mits by conducting an annual tune-up. These units must also conduct testing and monitoring activi ties for CO to demonstrate compliance with the numerical emission limits. Option 3N also includes a numerical PM emission limit f or coal, biomass, and liquid boilers, based on the NSPS limits applicable to each of these categories. Since all coal units are subject to mercury emission limits, they are expected to m eet a PM GACT limit of 0.03 lb/mmBtu without any additional control requirements. The NSPS PM limit for biomass is 0.03 lb/mmBtu, which is based on the performance of an electr ostatic precipitator (ESP). Since biomass units greater than 30 mmBtu/hr are already subject to this limit under the NSPS, this cost analysis applies the costs for an ESP to units les s than or equal to 30 mmBtu/hr. The NSPS PM limit for liquids is also 0.03 lb/mmBtu. Based on the calculated average baseline emission factors analysis distillate liquids are expected to mee t that limit without any additional control. 5 However residual liquid units are expected to install a fabr ic filter to meet the PM emission limit. Under option 3N, all boilers less than or equal to 30 mmB tu/hr are estimated to incur costs to test for PM and CO, at an estimate cost of $14,000 per year. Boilers greater than 30 mmBtu/hr will incur PM stack testing costs under the NSPS. Coal boilers are estimated to incur additional costs to test for mercury and the cost to co nduct tests for PM, CO, and Hg is estimated to be $19,000 per year.



### 3.8 Option 4N Option 4N includes mercury and CO emission limits for coa l units greater than 10 mmBtu/hr. Under option 4N liquid and biomass boilers are n ot subject to numerical emission limits for mercury or CO and there are no costs included in the impacts analysis to install add-on controls for mercury or CO control or conduct mercury o r fuel analysis or stack testing. This cost impacts analysis estimates an biennial tune-up to me et GACT requirements for all the biomass and liquid fuel units.13

Option 4N also includes a numerical PM emission limit f or coal, biomass, and liquid

boilers. The emission limits are set for units betwee n 10 mmBtu/hr and 30 mmBtu/hr respectively. Coal units in this range are expected to mee t emission limits of 0.42 lb/mmBtu. These mid-range Biomass boilers are subject to an emissi on limit of 0.069 lb/mmBtu, and liquid units in this range must meet an emission limit of 0.03 lb /mmBtu. All units greater than or equal to 30 mmBtu/hr, regardless of fuel type, are expected to meet a PM GACT limit of 0.03 lb/mmBtu. Coal units are expected to meet this limit using the same device installed for mercury control. Biomass units are expected to meet the PM em ission limit using an electrostatic precipitator (ESP). Based on the calculated average base line emission factors analysis distillate liquids are expected to meet that limit without any additional control. 5 However residual liquid units are expected to install a fabric filter to meet t he PM emission limit. Under option 4N, all boilers from 10 mmBtu/hr to 30 mmBtu/hr are estimated to incur costs to test for PM, at an estimate cost of $8,000 per year. Boilers greater than 30 mmBtu/hr will incur PM stack testing costs under the NSPS. Coal bo ilers are estimated to incur additional costs to test for mercury and CO the cost to conduct tes ts for PM, CO, and Hg is estimated to be $19,000 per year.



### 3.9 Summary of Cost Impacts In the final rule, option 4E is the option selected fo r existing boilers and option 4N is the option selected for new boilers. Table 1 summarizes t he costs of the promulgated option for new and existing boilers at area sources of HAP. Appendix A o f this memorandum provides a detailed summary of the costs for each model unit.

Table 1: Summary of Costs of Promulgated Options Costs shown in $10 6 (2008) with capital recovery estimated at 7%

Type of Unit Option Number

of Boilers TAC TAC considering fuel savings Testing &

Monitoring TAC Control TAC Control TCI New 4N 6,779 $48 $51.3 $25 $36 $100

Existing 4E 182,677 $436 $51.6 $7 $429 $1,29514



## 4.0 METHODOLOGY FOR ESTIMATING EMISSION REDUCTIONS

This section discusses the methodology used to estimate em ission reductions from boilers at both existing and new facilities and it presents a summ ary of the results for the regulatory options 1E/1N and 4E/4N.



### 4.1 Emission Reductions from Existing Boilers

Each model area source boiler was assigned baseline em issions based on the calculated baseline averages for existing major source combustion units in the same size and fuel subcategory. The development of area source model units a nd the procedures and results of the baseline emissions analysis is presented in other memor anda. 5-6

Emission Reductions for Option 1E Emission reductions for all pollutants were calculated on a ton per year basis. Emission reductions of Hg and CO were calculated by subtracting the baseline emissions assigned to each model unit from the MACT floor (or GACT) emission lim its corresponding to the subcategory for each model boiler. A detailed discussion of the pr ocedures and results of the MACT floor analysis is presented in another memorandum. 1

For all units expected to install a fabric filter to m eet the mercury MACT floor emission limits, this fabric filter achieves a co-benefit of r educing emissions of PM and non-mercury

metallic HAP. To calculate the PM emission reductions from units expected to install a fabric filter, the baseline emissions assigned to each model boiler were subtracted from the calculated average baseline emission factor corresponding to a fabric filter level of control in the same fuel category. For example, the PM baseline emission fac tor for uncontrolled or multiclone-equipped biomass boilers is 0.27 lb/mmBtu, and the calculated basel ine emission factors for biomass boilers equipped with a fabric filter is 0.004 lb/mmBtu. The emission reductions were estimated using the difference of these two factors, or 0.266 lb/mm Btu. The methodology used to calculate average baseline emission factors for different fuel an d control configurations is discussed in15

another memorandum. 5 It was assumed that the remaining boilers that did not install a fabric filter will install a cyclone or multiclone to reduce P M emissions. Multiclones were identified as

a GACT level of control for PM. Emission reductions fo r units expected to install a multiclone were estimated by multiplying the baseline emissions of each model unit by the expected PM control efficiency of a multiclone specific to the f uel category. These control efficiencies for

various control devices are detailed in another memorandu m. 5 Model units with a design capacity greater than 10 mmBtu/hr were expected to already have a multiclone installed as a baseline level of control, so no additional PM emission reductions were estimated from these units, unless the unit installed a fabric filter for mercury control. To estimate the reductions in other non-mercury metalli c HAP, the percent reduction in filterable PM was calculated for each model boiler expe cted to install a fabric filter for mercury control. This percent reduction was multiplied by the bas eline emissions for each of the nonmercury metallic HAP. Since fabric filters capture fine particulate, this analysis assumes that each model boiler would achieve an identical percent reduct ion from baseline emissions for each non-mercury metallic HAP as was achieved for PM. For mo del boilers that were expected to install a multiclone to meet the PM GACT limit, a 10 per cent reduction was estimated for nonmercury metallic HAP. PM2.5 emissions comprise a fraction of total filterable PM emissions depending on the fuel combusted and control device configuration installed on the unit. The methods used to

derive the contribution of PM2.5 to overall filterable P M are presented in other memoranda. 5 To

calculate emission reductions for PM2.5 for each model b oiler, the emission reductions for PM were multiplied by the applicable PM2.5 fraction. For any boiler conducting a tune-up or installing advanced comb ustion controls such as a replacement burner or linkageless boiler management system , a one percent gain in combustion efficiency was estimated, resulting in an estimated one percent emissions reduction of all pollutants. Efficiency gains reduce fuel use, and in turn, emissions of hazardous air pollutants. 8 A one percent reduction in emissions for these pollutants was estimated by multiplying the baseline emissions for each unit by a factor of 0.01.

To convert emission reductions from an emission rate on a heat input basis to an annual emission rate, Equation 2 was used:16

Annual Emission Rate (tpy) = ER HI * 0.0005 * Op hours * CF (Equation 2) Where: ER HI = emission rate (lb/mmBtu) 0.0005 = conversion factor, lbs per ton Op hours = annual operating hours, assumed 8760 (adjusted using capacity f actor) CF = annual average capacity factor, 0.68

To convert emission reductions from a concentration bas is to an annual emission rate, Equations 3 and 4 were used:

Annual Emission Rate (tpy) = ER C * 0.000001 * Q S * 60 * Op hours * MW * 0.0026 * 0.0005 * (20.946 – O 2 ) / (20.946 – Std O 2 ) * CF (Equation 3) Where: ER C = emission concentration (ppm @ 3% O 2 ) 0.000001 = conversion factor, ppm to parts Q S = exhaust flowrate (dscfm) 60 = conversion factor, minutes to hours Op hours = annual operating hours reported in 2008 survey (hours/year) MW = molecular weight of pollutant, in lb per lb-mole 0.0026 = conversion factor, lb-mole per dry standard cubic foot of gas 0.0005 = conversion factor, lb per ton 20.946 = percentage of oxygen in ambient air O 2 = percentage of oxygen assumed in exhaust gas Std. O 2 = 3 percent oxygen in standardized emission concentrati on for final rule. CF = annual average capacity factor, 0.68

Annual Emission Rate (tpy) = ER C * 0.0283 * Q S * 60 * Op hours * 0.000000001 * 0.0022 * 0.0005 * (20.946 – O 2 ) / (20.946 – Std O 2 ) * CF (Equation 4) Where: ER C = emission concentration (ng/dscm @ 7% O 2 ) 0.0283 = conversion factor, dry standard cubic meter per dry s td. cubic foot Q S = exhaust flowrate (dscfm) 60 = conversion factor, minutes per hour Op hours = annual operating hours reported in 2008 survey (hours/year) 0.000000001 = conversion factor, ng to g 0.0022 = conversion factor, g per lb 0.0005 = conversion factor, lb per ton 20.946 = percentage of oxygen in ambient air O 2 = percentage of oxygen assumed in exhaust gas Std O 2 = 7 percent oxygen in standardized emission concentratio n for final rule. CF = annual average capacity factor, 0.6817

Converting concentrations to an annual emission rate re quired an oxygen concentration and exhaust flowrate estimated for each specific fuel t ype. The development of these assumptions and estimates is presented in another memor andum. 4

Emission Reductions for Option 4E The same calculations discussed for estimating emissi on reductions for option 1E were applied to all large coal boilers. For small model boile rs, the emission reductions were based on a one percent gain in efficiency expected from the biennial tune-up work practice standard. For large biomass and liquid units no add-on controls for PM or mercury are expected since these units are not subject to numerical emission limits for P M or Hg. Instead, a similar one percent gain in efficiency is expected to occur as a result of con ducting an annual tune-up or installing advanced combustion controls necessary to meet the CO numerical limit in each category. Efficiency gains reduce fuel use, and in turn, emissions of hazardous air pollutants. A one percent reduction in all types of emissions was estimat ed by multiplying the baseline emissions for each unit by a factor of 0.01. A summary of the esti mated emission reductions at existing units for all options is located in Appendix B-1

.



### 4.2 Emission Reductions from New Boilers

Based on industrial and commercial fuel consumption projec tions from the EIA and a history of boiler installation dates in the boiler insp ector inventory, there are 6,779 new area source boilers expected to come on-line by 2013. 7 These new projected boilers are expected to fire biomass, coal, and liquid fuels. An average (mean) design capacity of area source boilers firing similar fuel type, in the same size category, and in the same sector (industrial or commercial) was estimated to develop new model units repre sentative of the existing boiler inventory. New model units were assigned baseline emissio ns in the same manner as existing area source model units. The projection of new model area source boilers and the procedures and results of the baseline emissions analysis is presen ted in other memoranda. 2

As discussed in Section 3.4, the NSPS for Industrial, Com mercial and Institutional Boilers (40 CFR part 60, subparts Db, Dc) (NSPS) were revie wed to identify the expected baseline level of control for projected new units. Then, the average baseline emission factor18

corresponding to the expected level of control and fuel c ategory was assigned to each new model boiler. New biomass boilers larger than 30 mmBtu/hr wer e expected to install an ESP; new coal boilers larger than 75 mmBtu/hr were expected to install a fabric filter and wet scrubber; new coal boilers between 30 and 75 mmBtu/hr would only have a fabr ic filter installed and were expected to meet the SO2 limits in the NSPS by using coals with a low sulfur content; new boilers larger than 30 mmBtu/hr and combusting liquid fuels were expected to install a fabric

filter. All new boilers less than 30 mmBtu/hr would hav e no add-on controls. For this impacts analysis, it was assumed that all new solid fuel units would be stokers, since stoker boilers are the most common type of solid fuel boilers and all new units would have NOx control installed as a baseline control, regardless of fuel. Based on the EIA fuel projections, all new coal boilers are projected to be less than 10 mmBtu/hr and the only 49 mode l boilers firing biomass are expected to exceed 30 mmBtu/hr.

Emission Reductions for Option 1N After an appropriate baseline level of control was deter mined for each model unit, an average baseline emission factor was calculated for exi sting units within the same fuel category and having the same level of control was assigned to each model boiler. The NSPS specifies PM and SO2 limits for new solid- and liquid-fired combustion u nits based on heat input. It was assumed that all new solid and liquid units would be const ructed to meet these limits and those limits were used as baseline emission values, where appl icable. For units less than 30 mmBtu/hr, the baseline emissions for PM were estimated assuming t he unit was uncontrolled and the target

PM emission limit from the NSPS was used as the GACT level of control. The baseline

emissions for each unit were subtracted from the new s ource MACT floor for Hg and CO and GACT emission limit for PM corresponding to each unit’s subcategory. The same calculations

discussed in Section 4.1 of this memo were used to estimate the reductions for new units.

Emission Reductions for Option 4N For new coal boilers, the emission reductions were cal culated using the same methods discussed for Option 1N above. For new biomass boilers l ess than 30 mmBtu/hr, emission reductions for PM were calculated by subtracting the PM NSPS emission limits from a baseline emission factor representing uncontrolled units. Since a n ESP is not expected to be very effective19

at capturing mercury emissions, mercury emissions reducti ons from all biomass units were estimated based on a one percent efficiency improvement, resulting from annual tune-ups or other combustion controls expected to occur in order to de monstrate compliance with CO emission limits. For new biomass boilers greater than or equal to 30 mmBtu/hr, there were no estimated additional PM or non-Hg metallic HAP emissio n reductions since these larger biomass boilers are already expected to be in compliance with a PM NSPS limit using an ESP. New residual liquid boilers less than 30 mmBtu/hr were expe cted to install a fabric filter

to meet the PM emission limit. Since a fabric filter is effective at capturing fine particulate, additional emission reductions for mercury were calculat ed by subtracting the average baseline emission factor for heavy liquid boilers equipped with a f abric filter from the average baseline emission factor corresponding to an uncontrolled heavy li quid unit. The average baseline emission factor for PM at uncontrol led distillate liquid units is less than the NSPS emission limit for liquid units. As a res ult, no additional PM, Hg, or non-Hg

metallic HAP emission reductions were estimated from ins talling additional PM controls. Instead, these reductions were estimated based on a one pe rcent efficiency improvement, resulting from annual tune-ups or other combustion controls expected to occur in order to demonstrate compliance with CO emission limits. Under this option, new small units do not qualify for the same tune-up work practice standards that apply to existing units since it is expected that new units can be designed to allow for stack test diameters that would be compatible with E PA test methods. A summary of the estimated emission reductions at for all new source opti ons is located in Appendix B-2

.



## 5.0 METHODOLOGY FOR ESTIMATING SECONDARY IMPACTS

Secondary impacts include the solid waste and electricity required to operate air pollution control devices, as well as the additional energy savings resulting from improved combustion controls or work practices required by the NESHAP. This s ection documents the inputs and equations used to estimate these secondary impacts, and it summarizes the impacts at existing units under promulgated regulatory option 4E and new units un der promulgated regulatory option 4N. Table 5-1 summarizes the secondary impacts of this promulgated NESHAP.20

Appendices C-1 and C-2 present a detailed breakdown of the s econdary waste and energy impacts from each subcategory of existing and new boilers, respectively.

Table 5-1: . Summary of Secondary Impacts

Impact New Units (Option 4N) Existing Units (Option 4E)

Solid Waste (tons/yr) 540 1,800

Purchased Electricity (kW-hr/yr) 8.0 million 25.4 million

CO2 Emissions from Electricity (tons/yr) 5,300 16,900

Energy Savings* (tBtu/yr) 2.3 19.6 * Energy savings is calculated for units in the coa l and liquid subcategories. The secondary impacts were calculated using algorithms and assumptions described in

another memorandum. 3 These algorithms and assumptions were applied to the exi sting boilers, where the baseline emissions for each unit exceeded the pro mulgated MACT floor emission limit. For new units, the algorithms and assumptions were applied to model units representing units expected to come online between 2010 and 2013, when the baseli ne emissions for each model exceeded the promulgated MACT floor or GACT emissio n limit for new units. The methodology used to assign baseline emission factors to n ew and existing units are discussed in

another memorandum. 5



### 5.1 Solid Waste Impacts Solid waste is generated from collecting dust and fly ash i n fabric filters or ESP control devices. Solid waste impacts were estimated for every u nit expected to install a fabric filter to meet mercury emission limits, or install an ESP to mee t PM emission limits. The total national solid waste amounts in Table 5-1 were determined by adding the per unit solid waste estimates for all new and existing units, respectively. To estimate the solid waste contribution from each of these control devices, the variables were calculated ba sed on characteristics reported for each

model unit. The calculations used to estimate each varia ble and the quantity of solid waste generated are provided in another memorandum. 3 The solid waste (dust, fly ash) generated by the use of an electrostatic precipitator was calculated when an electrostatic precipitator was dete rmined to be necessary to meet the GACT21

emission limits for PM. Estimates of the solid waste collected in an ESP was based on several variables including: exhaust flow rate from the combustion u nit to the control device (acfm); the inlet loading of particulate matter to the control device (gr/acfm); operating hours (hr/year) and the efficiency of the control device required to meet the PM emission limits in the promulgated NESHAP. The solid waste generated from the collection of dust an d fly ash in a fabric filter was

calculated when a fabric filter was determined to be nec essary to meet the promulgated NESHAP emission limits for particulate matter and/or mercury . The calculation required the use of three variables, including: exhaust flow rate from the combustion u nit to the control device (dscfm); operating hours (hr/year) and the inlet loading of particu late matter to the control device (gr/acfm).



### 5.2 Electricity Impacts The amount of electricity required to operate a control device was calculated for an electrostatic precipitator and fabric filter. These im pacts were assessed for every unit that was estimated to require particulate matter control. Electr icity requirements are one output of the cost algorithms used in the analyses, so no additional cal culations were necessary. For some units, an electrical demand from multiple control devices was estimated. The total national electricity demand in Table 5-1 was determined by adding the pe r unit solid waste estimates for all new and existing units, respectively. To estimate the e lectricity demand from each of these control devices, a set of variables were calculated bas ed on characteristics assigned to each model unit. The constants, variables, and calculations used to estimate each variable and the electricity demand to operate the control devices are pro vided in another memorandum. 3



### 5.3 Greenhouse Gas Emissions from Electricity Usage Since Greenhouse Gases are generated from electricity pro duction, an estimate of carbon dioxide emissions was generated for the electricity impac ts of the add-on air pollution control devices. The total electricity impact amount was multip lied by the national average carbon

monoxide emission factor for carbon dioxide emissions from EPA’s 2005 e-GRID to obtain the expected annual carbon dioxide emissions. 9 No carbon dioxide emissions were estimated for boilers conducting a boiler tune-up since no electricity impacts were estimated for those units.22



### 5.4 Energy Savings Impacts The energy savings from combustion controls such as low N Ox burners or linkageless boiler management systems, and work practice standards, including a tune-up, and implementing the energy audit findings with a short-term payback can im provements in efficiency, thereby reducing fuel consumption. Although these combustion improv ements have been documented to achieve efficiency gains between 5 and 10 percent from the b aseline operating conditions, this secondary impacts analysis estimates a 1 percent efficie ncy gain, to be conservative and consistent with the assumptions made in Section 3.1 of t his memorandum. Quantifying the exact gains in efficiency from each of these work practice st andards is difficult, and may depend on the baseline operating efficiency of each unit. Section 3.1 discusses the fuel savings impacts in terms of annualized cost savings to each boiler, and the national energy savings presented in Ta ble 5-1 of this section follows the same methodology as was discussed in Section 3.1 and reflect the savings from boilers in the coal and liquid fuel categories only.



### 5.5 Estimating Secondary Impacts for Regulatory Opt ions 4E/4N Regulatory Options 4E for existing and 4N for new units are both described in detail in Section 2 of this memorandum. For the secondary impacts analysis at existing units under option 4E, the waste and electricity impacts were only assesse d for large units (those greater than or equal to 10 mmBtu/hr) that are in the coal subcategory. Seco ndary impacts of solid waste and electricity were not assessed for the liquid and biomass subcategories because these boilers were not subject to PM or Hg numerical emission limits and w ere not expected to install add-on controls. Energy savings were estimated for all units f iring anything other than biomass since all units were expected to conduct a tune-up or install combustio n controls. For new units under option 4N, the solid waste and elect ricity impacts were assessed for any size unit firing coal, liquid, or biomass, using the NSPS limit of 0.03 lb/mmBtu for PM. A one percent energy savings was estimated for all units f iring coal or liquids that were estimated to require a tune-up to meet the CO limits from new boile rs. Both tune-ups and combustion controls improve the efficiency of the unit, thereby reduc ing energy consumption.



## 6.0 REFERENCES23

1. Singleton, A. and B. Long, ERG. Revised MACT Floor and GACT Analysis for the Industrial, Commercial, and Institutional Boilers N ational Emission Standards for Hazardous Air Pollutants – Area Source . January, 2011.

2. Singleton, A., ERG. New Unit Analysis Industrial, Co mmercial, and Institutional Boilers National Emission Standards for Hazardous Air Pollutants – Area Source. April, 2010.

3. Singleton, Aand S. McClutchey ERG. Revised Methodology for Estimating Control Costs for Industrial, Commercial, Institutional Boiler s for the National Emission Standards for Hazardous Air Pollutants – Area Source. Ja nuary, 2011.

4. Singleton, A. and S. McClutchey, ERG. Revised Methodolo gy for Estimating Control Costs for Industrial, Commercial, Institutional Boiler s and Process Heaters National Emission Standards for Hazardous Air Pollutants – Major SourceJanuary, 2011.

5. Gibson, G. and A. Singleton, ERG. Revised Development of Baseline Emission Factors for Boilers and Process Heaters at Commercial, Industri al, and Institutional Facilities. January, 2011.

6. Singleton, A., ERG. Methodology for Developing Model Units for Industrial, Commercial, and Institutional Boilers National Emissio n Standards for Hazardous Air Pollutants – Area Source. April, 2010.

7. U.S. Department of Energy. Energy Information Adminis tration. Annual Energy Outlook 2006 (Early Release) with Projections to 2030. Figure 3. Ene rgy Consumption by Fuel, 1980-2030 (quadrillion Btu).

8. Delta Institute. Sector -Based Based Pollution Prevention: Toxic Reductions through Energy Efficiency and Conservation Among Industrial Boilers. July 2002. Located online at http://www.delta-institute.org/publications/boilers/SectorBa sedP2.pdf

9. U.S. Environmental Protection Agency. The Emissions & G eneration Resource Integrated Database (eGRID). 2007. Located online at: http://www.epa.gov/cleanenergy/documents/egridzips/eGRID2007V1_1_ year05_Summa ryTables.pdf